It is known in the art of oil recovery, and particularly in the enhanced recovery of oil from subsurface reservoirs, to employ the use of a downhole injected gas for increasing the amount of oil that can be produced from a reservoir. At times, this process is referred to as enhanced oil recovery (EOR) or tertiary recovery (as opposed to primary and secondary recovery).
Enhanced oil recovery using carbon dioxide gas is a well understood and publicized technology that involves injecting carbon dioxide gas into a reservoir. The special properties of carbon dioxide allow its EOR application in light, medium and heavy oil reservoirs in either of miscible or immiscible modes.
Injected carbon dioxide is known to dissolve readily in oil and reduce the viscosity of oil housed in a reservoir, thus allowing the oil to flow into a producing well and thereby be produced to surface. Furthermore, reservoir injected carbon dioxide can maintain reservoir pressure and improve oil displacement because the interfacial tension between oil and rock matrix is reduced. Typically, current commercial carbon dioxide enhanced oil recovery is conducted by injecting gaseous carbon dioxide under very high pressures (>13,000 kPa) into light to medium density oil (>22.3° API) bearing reservoirs at depths greater than 1,300 meter. High injection pressures are required to force the carbon dioxide gas to completely dissolve into the oil as a solvent thereby reducing oil viscosity and residual oil saturation.
There are, however, known drawbacks to using carbon dioxide for EOR or other projects involving oil recovery. For example, it has long been recognized that there can be limited access to high purity carbon dioxide gas at a reasonable price. Furthermore, a high initial capital investment is required to store, transport and inject high pressure gaseous and liquid carbon dioxide. Large scale carbon dioxide EOR projects require a reliable source of carbon dioxide, at a reasonable cost, either from a nearby natural carbon dioxide source or a nearby facility that collects and captures carbon dioxide. Small scale carbon dioxide EOR projects typically do not have access to such cost effective resources.
Another drawback when using carbon dioxide for conventional EOR is that diffusion of carbon dioxide gas into oil is typically a slow process. It is believed, however, that carbon dioxide gas generated inside a reservoir may allow for effervescence that can induce convectional mixing that increases the rate of carbon dioxide gas diffusion into oil.
U.S. patent application Ser. No. 13/898,438 to Mahmoud addresses some of the drawbacks of using carbon dioxide for EOR discussed above, by injecting a polyamino carboxylic acid chelating agent into a carbonate rock matrix reservoir allowing for the in situ generation of carbon dioxide. The process contemplated by Mahmoud, however, is only applicable and limited to reservoirs comprising carbonate rock as the carbon dioxide is sourced from the carbonate rock itself.
The use of carbon dioxide for conventional EOR has other drawbacks in the context of unconsolidated and weakly consolidated reservoirs. For example, it is believed that gas diffusion alone by conventional carbon dioxide gas injection EOR cannot directly physically weaken the reservoir rock matrix integrity even for unconsolidated and weakly consolidated reservoirs.
It is known to those skilled in the art of heavy oil recovery that it is uneconomical to produce heavy oil (<22.3° API) and extra heavy oil (<10.0° API) by conventional mean of Darcy flow through a porous media as occurs during light to medium oil production. Heavy oil reservoirs tend to be situated at shallower depths (<1,300 meter) with lower reservoir pressures (<13,000 kPa) where the rock formation tends to be unconsolidated in nature. Light to medium oil reservoirs tend to be found at depths greater than 1,300 meter where the rock formation tends to be consolidated in nature.
The term “heavy oil” implies that the oil has high oil density because it contains higher molecular weight molecules such as long chain saturates, asphaltene, resin and/or wax which are more viscous than light and medium oil.
Heavy oil production from unconsolidated sandstone reservoirs became popular in the late 1980s, when progressive cavity pumps were employed allowing the well to produce both reservoir sand/material and fluid. Heavy oil production from unconsolidated sandstone reservoirs can use this production method, referred to as cold heavy oil production with sand (CHOPS), which involves induced sand production so that high permeability conduits called “wormholes” can grow and expand deep into the unconsolidated reservoir allowing for more reservoir oil to become accessible.
The CHOPS process involves the transport of reservoir sand and fines material along with the reservoir heavy oil and formation brine through extremely highly permeable wormholes into a wellbore. Typically, active wormholes are open channels, with high permeability, running in 100,000's to 10,000,000's Darcy, with diameters as large as 10 to 20 centimeter. As long as sand and/or loosened reservoir material is continuously dislodged and produced to surface, the wormhole network will continue to grow in length and diameter outwardly and deeper into the reservoir allowing for more reservoir oil to become accessible.
The typical sand cut of producing CHOPS wells is 5% to 40% of the production volume. Therefore, the maximum sand production translates to the maximum heavy oil recovery in unconsolidated and weakly consolidated reservoirs employing CHOPS depletion mechanisms.
Wormholes will continue to grow when the pressure difference between the reservoir pressure and the drawdown pressure at the tip of the wormhole exceeds the critical pressure gradient needed to overcome the cohesive strength of the reservoir sand matrix. The cohesive strength of an unconsolidated formation can range from about 0 to 5,000 kPa, and 5,000 to 20,000 kPa for a weakly consolidated formation. It is a common practice to aggressively drawdown a new CHOPS well to create maximum pressure gradient at the wellbore perforation to initiate sand production to form wormholes. The path and speed of wormhole growth will be dictated by the orientation of minimum cohesive strength of the unconsolidated reservoir at the wormhole leading tip point. The degree of cementation, sand grain size, capillary pressure, and oil viscosity are some factors that may affect the cohesive strength of an unconsolidated reservoir.
In situations where a growing wormhole encounters a region having a high sand matrix cohesive strength that cannot be overcome by the pressure gradient, sand failure is not possible, thus sand production ceases thereby rendering the CHOPS well uneconomical to produce. The timing and location where wormhole growth is halted may be unpredictable due to the heterogeneity of the rock formation of a reservoir.
Wormhole growth can also be halted by intentionally stopping the well production. It may be necessary to shut-in a CHOPS well for a period of time due to operational interruptions such as surface facility upsets or well servicing. Under these circumstances, it is common when a shut-in CHOPS well returns to production mode, the oil production rate is reduced when compared to the rate before well shut-in. Shutting in an active CHOPS well may halt the cascading sand production mechanism and cause settling of suspended sands and fines inside the wormholes. This may either result in plugging up of the wormholes and/or collapsing some wormholes.
Wormhole growth relies on continuous reservoir sand failure and the CHOPS process will cease when the sand and fluid flow to the wellbore is halted. There is a need for methods that enhance the recovery of oil from unconsolidated and weakly consolidated reservoirs, and that can initiate, re-initiate and restore wormhole growth for a CHOPS recovery process.